CA1282685C - Preventing plugging by insoluble salts in a hydrocarbon-bearingformation and associated production wells - Google Patents
Preventing plugging by insoluble salts in a hydrocarbon-bearingformation and associated production wellsInfo
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- CA1282685C CA1282685C CA000547748A CA547748A CA1282685C CA 1282685 C CA1282685 C CA 1282685C CA 000547748 A CA000547748 A CA 000547748A CA 547748 A CA547748 A CA 547748A CA 1282685 C CA1282685 C CA 1282685C
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- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/52—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning
- C09K8/528—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning inorganic depositions, e.g. sulfates or carbonates
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- Materials Engineering (AREA)
- Organic Chemistry (AREA)
- Separation Using Semi-Permeable Membranes (AREA)
- Organic Low-Molecular-Weight Compounds And Preparation Thereof (AREA)
- Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
Abstract
Docket 860025-A
PREVENTING PLUGGING BY INSOLUBLE SALTS IN A HYDROCARBON-BEARING
FORMATION AND ASSOCIATED PRODUCTION WELLS
Abstract Plugging in fluid passageways of a subterranean hydrocarbon-bearing formation or associated production wells caused by the accu-mulation of insoluble salt precipitates therein which results from an in situ interaction between precipitate precursor ions in an injection water and resident ions already occurring in the formation is prevented by removing the precursor ions from the injection water by a reverse osmosis membrane before injecting the water into the formation.
RFB/jaa
PREVENTING PLUGGING BY INSOLUBLE SALTS IN A HYDROCARBON-BEARING
FORMATION AND ASSOCIATED PRODUCTION WELLS
Abstract Plugging in fluid passageways of a subterranean hydrocarbon-bearing formation or associated production wells caused by the accu-mulation of insoluble salt precipitates therein which results from an in situ interaction between precipitate precursor ions in an injection water and resident ions already occurring in the formation is prevented by removing the precursor ions from the injection water by a reverse osmosis membrane before injecting the water into the formation.
RFB/jaa
Description
Descriptio PREVENTING PLUGGING BY INSOLUBLE SALTS IN A HYDRUCARBON-eEARING
FORMATION AND ASSOCIATED PRODUCTION WELLS
Back~round of the Invention 05 Technical Fleld:
The present invention relates to a process facilitating hydro-carbon recovery from a subterranean formation and more specifically to a process preventing plugying of the formation and associated production wells.
Description of Related Art:
Water is commonly injected into subterranean hydrocarbon-bearing formations by itself or as a component of miscible or immis-ci~le displacement fluids to recover hydrocarbons therefrom. Injec-tion water can be obtained from a number of sources including brine produced from the same formation, brine produced from remote forma-tions, or sea water. All of these waters typically have a high ionic content relative to fresh water.
Some ions present in an injection water can benefit hydrocarbon production. For example, certain combinations of cations and anions, including K+, Na+, Cl-, Br~, and OH-, can stabi-lize clay to varying degrees in a formation susceptible to clay dam-age from swelling or particle migration.
However, other ions present in the injection water can produce harmful effects in situ. For example, divalent S04= anions in the injection water are particularly problematic because S04= forms salts with many naturally-occurring cations already present in the formation, such as Ba++. The resulting salts can be relatively insoluble at the formation temperatures and pressures. Consequently they precipitate out of solution in situ. Solubility of the salts further decreases as the injection water is produced to the surface -2- Docket 860025-A
with the hydrocarbons because of pressure and temperature decreases in the production well.
The precipitates of the insoluble salts accumulate in subter-ranean fluid passageways as crystalline structures which ultimately 05 plug the passageways and reduce hydrocarbon production. The effects of plugging are most severe in passageways located in the formation near wellDores and in production wells where it is rr,ore dif~icult for the produced fluids to circumvent blocked passageways.
Prior art solutions to the problem of formation and production well plugging focus on preventing or inhibiting crystal formation in situ by supplementing the injec-tion water with additives or back-flowing a well with produced formation water containing additives.
For example, ethylenediaminetetraacetic acid (EDTA) is a crystal modifier which can inhibit the in situ growth of crystals from insoluble salt precipitates. However, prior art processes are not totally satisfactory because the cost of chemical additives is sig-nificant and the cost ~scalates over the production life of the for-mation. FurthermoreJ the processes are ineffective without pain-staking process control to ensure proper stochiometric concentration and in situ mixing of the additives.
An effective process for preventing plugging in a hydrocarbon-bearing formation and associated production wells by insoluble salts ` is needed which overcornes the drawbacks oF the prior art. A process is needed which is relatively low cost and is relatively easy to control at the surface.
Summary of the Invention The present invention is a process for reducing or preventing plugging in fluid passageways of hydrocarbon-bearing formations and in production wells which is caused by the accumulation of insoluble salt precipitates therein. This objective is acnieved by removing most or all of the precursor ions of the insoluble salt precipitates from an injection water at the surface before the water is injected into the formation. Thus, insufficient precursor ions are available 3 Docket 860025-A
to react with ions already present in the formation to Form signifi-cant amounts of the insoluble salt precipitates.
The precursor ions of the insoluble salt precipitates are removed by means of a reverse osmosis membrane. The present inven-05 tion has several advantages because it reduces precipitate forrnation by removing the offending precursor ions, rather -than inhibitiny precipitate formation by adding chemical additives as in the prior art. Once the reverse osmosis unit of the present invention is in place, ongoing operating costs are considerably lower than injectiny chemical additives. ~ore importantly, process control in the pre-sent invention is much easier to perform and produces more effectiveresults because all process steps are conducted at the surface rather than in situ.
Description of Preferred Embodiments The present invention is a process for removing precursor ions from an injection water which form insoluble salt precipitates in situ when they contact resident ions already present in a subter-ranean hydrocarbon-bearing formation. The process substantially reduces or prevents the formation of the precipitates which undesir-ably accumulate and plug subterranean fluid passageways. As defined herein, subterranean fluid passageways encompass pores in a forma-tion matrix; formation anomalies such as fractures, voids, cavities, and vugs; and wells, including cased and uncased wellbores, tubing, and annuli between casing and tubing.
The precipitates are commonly termed insoluble salts, crystals, or scale and these terms may be used synonymously herein. Pluyging is defined herein as a substantial reduction in permeability and/or porosity of a fluid passageway to injection fluids or hydrocarbons.
The term injection water as used herein is any aqueous liquid which contains water and which is injected as a displacement fluid into a hydrocarbon-beariny formation via an injection well to facilitate the recovery of hydrocarbons from the formation via a production well. Thus~ water by itself or an aqueous solution containing water as the solvent are within the definition of injection water. Common 4_ Docket 86U025-~
displacement fluids such as aqueous polymer solutions and aqueous surfactant solutions can be injection water as defined herein.
The present process is broadly applicable to an injection water containiny precursor ions. Precursor ions are defined as ions which 05 form insoluble salt precipitates at the conditions of the formation or associated production wells when they contact resident ions in situ. Resident ions are defined as naturally or artifically occur-ring ions alrea~y present in the formation upon injection of the injection water. An associated production well is a well in fluid communication with the formation and which produces hydrocarbons therefrom.
The precursor ion can be an anion or cation, but in all cases it must be a different ionic species and oppositely charged to the resident ionic species it contacts in the formation. Whether an ion in an injection water is actually a precursor ion in any given case depends to a yreat extent on the resident ionic species which it contacts in si-tu. A yiven ion can be a precursor ion when injected into one formation, but not in another. For example, if My++ is injected into a formation and it contacts an OH- anion in situ, it will not form an insoluble precipitate. ~g++ is not a precursor ion in this case. But, if My++ contacts a C03= anion in situ when injected into another formation, it will form an insoluble precipi-tate. In this case, My++ is a precursor ion.
Althouyh many injection waters have a siynificant ion concen-tration, most ionic species contained in injection waters are notprecursor ions in a given formation. However, the present invention focuses on the removal from the injection water of those cations or anions which are precursors of insoluble salts in a given forma-tion. Specific ions which can be precursors of insoluble salt pre-cipitates according to the definition herein and to which the pre-sent invention is applicable include S04=, C03=, Fe++, Fe+++, Sr++, Ba++, Mg++, Ca+~, Al+++, and mixtures thereof.
The actual precursor ion concentration at which precipitation occurs for a given case is a function of many variables includiny the concentration of other ions in solution and the in situ ' :
' 5_ Docket 860025-A
conditions of temperature, pressure and pH, to name a fe~l. One of skill in the art can in many cases predict precipitation from data for the above-listed variables and apply the present process as a preventative before pluyging actually occurs. One can also apply 05 the present process as a remedial action after some in situ plugging is actually observed in order to prevent further pluyg~ng.
There is no fixed minimum threshold concentration of precursor ions in the injection water above which precipitation and plugging will occur in all cases. However, an injection water having a pre-cursor ion concentration above about 100 ppm can often form a plug-ging precipitate when contacted with the appropriate resident ion in situ. Thus, the present process is generally applicable when the injection water has a precursor ion concentration above about 100 ppm and preferably above about 500 ppm.
Resident ions already present in the formation which have been observed to form insoluble salt precipitates upon contact with the precursor ions of the injection water include Ba++, Sr++, My++, Ca++, Fe++, Fe++~, Al+++, C03=, S04=, and mixtures thereof. As noted above, whether an insoluble salt precipitate actually forms depends to a great extent on the yiven combination of precursor and resident ionic species which contact in situ. At a minimum, the two must be different species and oppositely charged.
Tile resident ions may be naturally occurring in the formation or may be artificially occurring in the formation as a result of some prior wellbore or formation treatment process. The resident ions need only be present in the formation at a sufficient concen-tration to form precipitates with the precursor ions at formation or production well conditions when they are injected into the formation.
The precipitate precursor ions are removed from the injection water by means of a reverse osmosis membrane. The membrane is housed in a conventional reverse osmosis unit. The feed -to the unit is an untreated injection water containing a water solvent and precipitate precursor ions in sufficient concentration to form ~X~26~
-6- Docket 860025-A
insoluble salt precipitates when injected into a formation of inter-est and contacted with resident ions already present therein. The water solvent is driven across the reverse osmosis membrane by a pumping pressure greater than the osmotic pressure of the untreated 05 injection water and a treated injection water is recovered as prod-uct on the side of the membrane opposite the feed. The precursor ions remain on the same side of the membrane as the feed to form a brine having a higher concentration of precursor ions than the feed, The brine is discharyed from the unit and disposed.
The treated injection water product has a substantially lower concentration of precursor ions than the feed. The concentration of precursor ions is sufficiently low such that the treated injection water product is substantially incapable of forming insoluble salt precipitates in sufficient quantities to plug fluid passageways in the formation or associated production wells when injected into the formation of interest. Although this value of concentration varies as a function of the formation conditions, it is generally advanta-geous to reduce the precursor ion concentration in the treated injection water product below about 500 ppm and preferably below about 100 ppm.
As stated above, the feed is maintained in the unit at a pres-sure above the osmotic pressure for the feed conditions and membrane type. The osmotic pressure can be determined by one of skill in the art. Generally the present process is operated within a pressure range of about 690 to about 6900 kPa. The process is usually oper-ated at the temperature of the feed, but is operable within a range of about 2 to about 200C. The process is operable across a wide range of pH. If desired, the pH of the feed can be adjusted to enhance the operation of the unit within a range of about 1 to about 13.
Any number of reverse osmosis membranes known in the art may be employed in the present invention. Materials comprising reverse osmosis membranes include cellulose acetate, polyamide, and sulfated polysulfone, to name a few. The reverse osmosis membrane should at least be capable of preventing significant amounts of precipitate -7 Docket 860025-A
precursor ions from entering the injection water product. The mem-brane may also eliminate other ions from the injection water product.
However, the membrane is preferably one which selectively pre-05 vents the precipitate precursor ions from passing across it from thefeed into the injection water product while at the same time allow-ing the water solvent and harmless ions to pass across it. The selectivity of a membrane is a function of the particular properties of the membrane, including the pore size of the membrane or the electrical charge of the membrane. One selects a melnbrane for use in the present invention based on these criteria and its experi-mental performance. For example, a polyamide membrane is particu-larly effective for selectively preventing the precursor ion S04=
from passing across ito A polyamide membrane manufactured by FilmTec Corporation, Minneapolis, Minnesota, U.S~A., having the trade mark NF-4a~ is especially preferred for removing S04- from an injection water.
A selective membrane allows harmless ions to pdSS across it into the treated injection water product~ These ions may even have a beneficial effect in the formation. For example, potential clay stabilizing ions, such as K+, Na~, Cl-, Br- and OH-, may be passed into the treated injection water product and subsequently injected into the formation to beneficially prevent clay swelling or particle migration if resident ions are not present in the formation which could form insoluble precipitates with these injected ions.
The reverse osmosis unit is preferably operated in a continuous manner, i.e., continuously feeding untreated injection water into the unit and continuously discharging a waste brine and a treated injection water product. The product output rate of the unit is, to a large part~ a function of the type and surface area of the mem-brane, the temperature and pressure of the unit, and the desired degree of precursor ion exclusion from the injection water product.
The optimum unit output is experimentally determined for a given set of conditions.
`~`'1~ ` i .
~L~87~
~8- Docket 860025-A
The product output should satisfy the injection water require-ment for a given hydrocarbon recovery application and is generally within a range of about 8.4g to about 84.9 1/m2-hr. The ra-tio of injection water product to waste brine discharged frorn the unit OSranges from about 0.2:1 to about 4:1 and preferably is about 3:1.
The unit is advantageously operated such that the percentage ion selectivity to the injec~ion water product for precursor ions is less than about 10% and preferably less than about 3%. Percentage ion selectivity to the product is defined as the ion concentration lOin the product divided by the ion concentration in the feed expressed as a percentage.
The present process is particularly advantageous as an adjunct to a hydrocarbon displacement process where the injection water has a different ionic makeup than the formation water and where plugging 15occurs in fluid passageways of a production well or a near wellbore environment of an injection or production well. The near wellbore environment is defined herein as a volume of the formation within a radius up to about 5 meters from the wellbore axis. Plugging in or near wellbores is most harmful to hydrocarbon production because 20fluids are less able to flow around plugged fluid passageways in these locations~ Fluids can flow around plugged passageways in the formation away from the wellbore because more alternative unplugged ~luid passageways exist as alternatives to flow.
The following examples illustrate embodiments of the present 25invention but are not to be construed as limiting the scope thereof.
, A synthetic injection water is treated in a reverse osmosis unit according to the present invention. The reverse osmosis mem-brane is a polyamide membrane haviny the trade mark FilmTec NF-40.
30The membrane is a spiral tube having an outside diameter of about 6.4 cm and a length of about 6.1 meters. The untreated injection water feed contacts the outside surface of the membrane and the injection water product is recovered from the inside surface of the membrane. The unit produces about 25 liters of injection water ~i .
~;~82~
g_ Docket 860025-A
product per square meter of membrane per hour. The product is about 75% by volume of the feed while the remaining 25% by volume of the feed is discharged as brine. The unit is operated at a tempera-ture of about 22C and a pressure of about 1590 kPa, which is above 05 the osmotic pressure of the feed.
The ion concentrations of the feed, product, and brine and the percentage ion selectivity to the product are shown in Table 1 below.
Table 1 Ion Ion Concentration mg/l% Ion Selectivity Type Feed Product Brine To Product Water -Li+ 1.9 1.8 2.2 94.7 Na+ 8,970 8,175 11,180 91.1 K+ 334 317 426 94.9 Mg++ 1,026 502 2,630 48.9 Ca++ 353 225 738 63.7 Sr++ 17 8 32 47.1 Cl~ 15,200 13,990 19,200 92.0 Br~ 78.3 72.3 100 92.3 S04= 2,575 80 10,400 3.1 TDS 29,380 23,615 47,660 80.4 pH 8.26 8.04 8.20 The results of Table 1 indicate that the mernbrane effectively excludes from the injection water product undesirable S04= ions which are precipitate precursors when contacted in situ with Ba++
resident ions. The S04= concentration in the injection water product is sufficiently low to prevent substantial pluyying in most cases when injected into a subterranean hydrocarbon-bearing forma-tion containing Ba++ resident ions. At the same time, the mem-brane allows a significant portion of the non-precursor ions to pass through the membrane into the injection water product, which can beneficially stabilize clay in situ.
'~
.` ' `
$~
-10- Docket 8600~ -A
EXAMPLE Z
Water flooding of a subterranean hydrocarbon-bearing formation~
which contains naturally occurring Ba+~ ions, with an untreated injection sea water, which has an S04= ion concentration of about 05 2800 ppm, results in BaS04 scale formation in situ. The scale plugs fluid passageways in the formation and the production tubing of associated hydrocarbon production wells. Production in one of the wells is observed to decrease from 132,000 liters of oil per hour to 33,000 liters of oil per hour due to the plugged tubing. Water pro-duced via the well contains 2000 ppm BaS04 precipitate. To prevent further plugging, the injection water is treated in a reverse osmosis unit prior to injection accordirg to the present invention.
The injection water is fed to the reverse osmosis unit at a temperature of about 25C and a pressure of abou~ 2000 kPa.
Seventy-five percent by volume of the untreated feed is recovered as treated injection wa~er product. The unit operates at a rate of 33 liters of injection water produc~ per square meter of membrane per hour. The unit is sized such that the total output of treated injection water product is 660,000 liters per hour. The S04= con-centration in the treated injectic~ water p:roduct is reduced to 6Q pEm. The entire treated injection water output of the unit is injected into the formation via injection wells in a water flooding process.
Oil and the injected water are produced from associated produc-tion wells in the formation, The produced water contains 114 ppm Z5 BaS04 precipitate, a significant reduction from the concentration of BaS04 in the produced water prior to treatment of the injection water. Furthermore, no significant decrease in oil production due to plugging is observed after treatment of the injection water.
While the foregoing embodiments of the invention have been described and shown, it is understood that all alternatives and modifications, such as those suggested and others, rnay be made thereto and follow in the scope of the invention.
.. ~
FORMATION AND ASSOCIATED PRODUCTION WELLS
Back~round of the Invention 05 Technical Fleld:
The present invention relates to a process facilitating hydro-carbon recovery from a subterranean formation and more specifically to a process preventing plugying of the formation and associated production wells.
Description of Related Art:
Water is commonly injected into subterranean hydrocarbon-bearing formations by itself or as a component of miscible or immis-ci~le displacement fluids to recover hydrocarbons therefrom. Injec-tion water can be obtained from a number of sources including brine produced from the same formation, brine produced from remote forma-tions, or sea water. All of these waters typically have a high ionic content relative to fresh water.
Some ions present in an injection water can benefit hydrocarbon production. For example, certain combinations of cations and anions, including K+, Na+, Cl-, Br~, and OH-, can stabi-lize clay to varying degrees in a formation susceptible to clay dam-age from swelling or particle migration.
However, other ions present in the injection water can produce harmful effects in situ. For example, divalent S04= anions in the injection water are particularly problematic because S04= forms salts with many naturally-occurring cations already present in the formation, such as Ba++. The resulting salts can be relatively insoluble at the formation temperatures and pressures. Consequently they precipitate out of solution in situ. Solubility of the salts further decreases as the injection water is produced to the surface -2- Docket 860025-A
with the hydrocarbons because of pressure and temperature decreases in the production well.
The precipitates of the insoluble salts accumulate in subter-ranean fluid passageways as crystalline structures which ultimately 05 plug the passageways and reduce hydrocarbon production. The effects of plugging are most severe in passageways located in the formation near wellDores and in production wells where it is rr,ore dif~icult for the produced fluids to circumvent blocked passageways.
Prior art solutions to the problem of formation and production well plugging focus on preventing or inhibiting crystal formation in situ by supplementing the injec-tion water with additives or back-flowing a well with produced formation water containing additives.
For example, ethylenediaminetetraacetic acid (EDTA) is a crystal modifier which can inhibit the in situ growth of crystals from insoluble salt precipitates. However, prior art processes are not totally satisfactory because the cost of chemical additives is sig-nificant and the cost ~scalates over the production life of the for-mation. FurthermoreJ the processes are ineffective without pain-staking process control to ensure proper stochiometric concentration and in situ mixing of the additives.
An effective process for preventing plugging in a hydrocarbon-bearing formation and associated production wells by insoluble salts ` is needed which overcornes the drawbacks oF the prior art. A process is needed which is relatively low cost and is relatively easy to control at the surface.
Summary of the Invention The present invention is a process for reducing or preventing plugging in fluid passageways of hydrocarbon-bearing formations and in production wells which is caused by the accumulation of insoluble salt precipitates therein. This objective is acnieved by removing most or all of the precursor ions of the insoluble salt precipitates from an injection water at the surface before the water is injected into the formation. Thus, insufficient precursor ions are available 3 Docket 860025-A
to react with ions already present in the formation to Form signifi-cant amounts of the insoluble salt precipitates.
The precursor ions of the insoluble salt precipitates are removed by means of a reverse osmosis membrane. The present inven-05 tion has several advantages because it reduces precipitate forrnation by removing the offending precursor ions, rather -than inhibitiny precipitate formation by adding chemical additives as in the prior art. Once the reverse osmosis unit of the present invention is in place, ongoing operating costs are considerably lower than injectiny chemical additives. ~ore importantly, process control in the pre-sent invention is much easier to perform and produces more effectiveresults because all process steps are conducted at the surface rather than in situ.
Description of Preferred Embodiments The present invention is a process for removing precursor ions from an injection water which form insoluble salt precipitates in situ when they contact resident ions already present in a subter-ranean hydrocarbon-bearing formation. The process substantially reduces or prevents the formation of the precipitates which undesir-ably accumulate and plug subterranean fluid passageways. As defined herein, subterranean fluid passageways encompass pores in a forma-tion matrix; formation anomalies such as fractures, voids, cavities, and vugs; and wells, including cased and uncased wellbores, tubing, and annuli between casing and tubing.
The precipitates are commonly termed insoluble salts, crystals, or scale and these terms may be used synonymously herein. Pluyging is defined herein as a substantial reduction in permeability and/or porosity of a fluid passageway to injection fluids or hydrocarbons.
The term injection water as used herein is any aqueous liquid which contains water and which is injected as a displacement fluid into a hydrocarbon-beariny formation via an injection well to facilitate the recovery of hydrocarbons from the formation via a production well. Thus~ water by itself or an aqueous solution containing water as the solvent are within the definition of injection water. Common 4_ Docket 86U025-~
displacement fluids such as aqueous polymer solutions and aqueous surfactant solutions can be injection water as defined herein.
The present process is broadly applicable to an injection water containiny precursor ions. Precursor ions are defined as ions which 05 form insoluble salt precipitates at the conditions of the formation or associated production wells when they contact resident ions in situ. Resident ions are defined as naturally or artifically occur-ring ions alrea~y present in the formation upon injection of the injection water. An associated production well is a well in fluid communication with the formation and which produces hydrocarbons therefrom.
The precursor ion can be an anion or cation, but in all cases it must be a different ionic species and oppositely charged to the resident ionic species it contacts in the formation. Whether an ion in an injection water is actually a precursor ion in any given case depends to a yreat extent on the resident ionic species which it contacts in si-tu. A yiven ion can be a precursor ion when injected into one formation, but not in another. For example, if My++ is injected into a formation and it contacts an OH- anion in situ, it will not form an insoluble precipitate. ~g++ is not a precursor ion in this case. But, if My++ contacts a C03= anion in situ when injected into another formation, it will form an insoluble precipi-tate. In this case, My++ is a precursor ion.
Althouyh many injection waters have a siynificant ion concen-tration, most ionic species contained in injection waters are notprecursor ions in a given formation. However, the present invention focuses on the removal from the injection water of those cations or anions which are precursors of insoluble salts in a given forma-tion. Specific ions which can be precursors of insoluble salt pre-cipitates according to the definition herein and to which the pre-sent invention is applicable include S04=, C03=, Fe++, Fe+++, Sr++, Ba++, Mg++, Ca+~, Al+++, and mixtures thereof.
The actual precursor ion concentration at which precipitation occurs for a given case is a function of many variables includiny the concentration of other ions in solution and the in situ ' :
' 5_ Docket 860025-A
conditions of temperature, pressure and pH, to name a fe~l. One of skill in the art can in many cases predict precipitation from data for the above-listed variables and apply the present process as a preventative before pluyging actually occurs. One can also apply 05 the present process as a remedial action after some in situ plugging is actually observed in order to prevent further pluyg~ng.
There is no fixed minimum threshold concentration of precursor ions in the injection water above which precipitation and plugging will occur in all cases. However, an injection water having a pre-cursor ion concentration above about 100 ppm can often form a plug-ging precipitate when contacted with the appropriate resident ion in situ. Thus, the present process is generally applicable when the injection water has a precursor ion concentration above about 100 ppm and preferably above about 500 ppm.
Resident ions already present in the formation which have been observed to form insoluble salt precipitates upon contact with the precursor ions of the injection water include Ba++, Sr++, My++, Ca++, Fe++, Fe++~, Al+++, C03=, S04=, and mixtures thereof. As noted above, whether an insoluble salt precipitate actually forms depends to a great extent on the yiven combination of precursor and resident ionic species which contact in situ. At a minimum, the two must be different species and oppositely charged.
Tile resident ions may be naturally occurring in the formation or may be artificially occurring in the formation as a result of some prior wellbore or formation treatment process. The resident ions need only be present in the formation at a sufficient concen-tration to form precipitates with the precursor ions at formation or production well conditions when they are injected into the formation.
The precipitate precursor ions are removed from the injection water by means of a reverse osmosis membrane. The membrane is housed in a conventional reverse osmosis unit. The feed -to the unit is an untreated injection water containing a water solvent and precipitate precursor ions in sufficient concentration to form ~X~26~
-6- Docket 860025-A
insoluble salt precipitates when injected into a formation of inter-est and contacted with resident ions already present therein. The water solvent is driven across the reverse osmosis membrane by a pumping pressure greater than the osmotic pressure of the untreated 05 injection water and a treated injection water is recovered as prod-uct on the side of the membrane opposite the feed. The precursor ions remain on the same side of the membrane as the feed to form a brine having a higher concentration of precursor ions than the feed, The brine is discharyed from the unit and disposed.
The treated injection water product has a substantially lower concentration of precursor ions than the feed. The concentration of precursor ions is sufficiently low such that the treated injection water product is substantially incapable of forming insoluble salt precipitates in sufficient quantities to plug fluid passageways in the formation or associated production wells when injected into the formation of interest. Although this value of concentration varies as a function of the formation conditions, it is generally advanta-geous to reduce the precursor ion concentration in the treated injection water product below about 500 ppm and preferably below about 100 ppm.
As stated above, the feed is maintained in the unit at a pres-sure above the osmotic pressure for the feed conditions and membrane type. The osmotic pressure can be determined by one of skill in the art. Generally the present process is operated within a pressure range of about 690 to about 6900 kPa. The process is usually oper-ated at the temperature of the feed, but is operable within a range of about 2 to about 200C. The process is operable across a wide range of pH. If desired, the pH of the feed can be adjusted to enhance the operation of the unit within a range of about 1 to about 13.
Any number of reverse osmosis membranes known in the art may be employed in the present invention. Materials comprising reverse osmosis membranes include cellulose acetate, polyamide, and sulfated polysulfone, to name a few. The reverse osmosis membrane should at least be capable of preventing significant amounts of precipitate -7 Docket 860025-A
precursor ions from entering the injection water product. The mem-brane may also eliminate other ions from the injection water product.
However, the membrane is preferably one which selectively pre-05 vents the precipitate precursor ions from passing across it from thefeed into the injection water product while at the same time allow-ing the water solvent and harmless ions to pass across it. The selectivity of a membrane is a function of the particular properties of the membrane, including the pore size of the membrane or the electrical charge of the membrane. One selects a melnbrane for use in the present invention based on these criteria and its experi-mental performance. For example, a polyamide membrane is particu-larly effective for selectively preventing the precursor ion S04=
from passing across ito A polyamide membrane manufactured by FilmTec Corporation, Minneapolis, Minnesota, U.S~A., having the trade mark NF-4a~ is especially preferred for removing S04- from an injection water.
A selective membrane allows harmless ions to pdSS across it into the treated injection water product~ These ions may even have a beneficial effect in the formation. For example, potential clay stabilizing ions, such as K+, Na~, Cl-, Br- and OH-, may be passed into the treated injection water product and subsequently injected into the formation to beneficially prevent clay swelling or particle migration if resident ions are not present in the formation which could form insoluble precipitates with these injected ions.
The reverse osmosis unit is preferably operated in a continuous manner, i.e., continuously feeding untreated injection water into the unit and continuously discharging a waste brine and a treated injection water product. The product output rate of the unit is, to a large part~ a function of the type and surface area of the mem-brane, the temperature and pressure of the unit, and the desired degree of precursor ion exclusion from the injection water product.
The optimum unit output is experimentally determined for a given set of conditions.
`~`'1~ ` i .
~L~87~
~8- Docket 860025-A
The product output should satisfy the injection water require-ment for a given hydrocarbon recovery application and is generally within a range of about 8.4g to about 84.9 1/m2-hr. The ra-tio of injection water product to waste brine discharged frorn the unit OSranges from about 0.2:1 to about 4:1 and preferably is about 3:1.
The unit is advantageously operated such that the percentage ion selectivity to the injec~ion water product for precursor ions is less than about 10% and preferably less than about 3%. Percentage ion selectivity to the product is defined as the ion concentration lOin the product divided by the ion concentration in the feed expressed as a percentage.
The present process is particularly advantageous as an adjunct to a hydrocarbon displacement process where the injection water has a different ionic makeup than the formation water and where plugging 15occurs in fluid passageways of a production well or a near wellbore environment of an injection or production well. The near wellbore environment is defined herein as a volume of the formation within a radius up to about 5 meters from the wellbore axis. Plugging in or near wellbores is most harmful to hydrocarbon production because 20fluids are less able to flow around plugged fluid passageways in these locations~ Fluids can flow around plugged passageways in the formation away from the wellbore because more alternative unplugged ~luid passageways exist as alternatives to flow.
The following examples illustrate embodiments of the present 25invention but are not to be construed as limiting the scope thereof.
, A synthetic injection water is treated in a reverse osmosis unit according to the present invention. The reverse osmosis mem-brane is a polyamide membrane haviny the trade mark FilmTec NF-40.
30The membrane is a spiral tube having an outside diameter of about 6.4 cm and a length of about 6.1 meters. The untreated injection water feed contacts the outside surface of the membrane and the injection water product is recovered from the inside surface of the membrane. The unit produces about 25 liters of injection water ~i .
~;~82~
g_ Docket 860025-A
product per square meter of membrane per hour. The product is about 75% by volume of the feed while the remaining 25% by volume of the feed is discharged as brine. The unit is operated at a tempera-ture of about 22C and a pressure of about 1590 kPa, which is above 05 the osmotic pressure of the feed.
The ion concentrations of the feed, product, and brine and the percentage ion selectivity to the product are shown in Table 1 below.
Table 1 Ion Ion Concentration mg/l% Ion Selectivity Type Feed Product Brine To Product Water -Li+ 1.9 1.8 2.2 94.7 Na+ 8,970 8,175 11,180 91.1 K+ 334 317 426 94.9 Mg++ 1,026 502 2,630 48.9 Ca++ 353 225 738 63.7 Sr++ 17 8 32 47.1 Cl~ 15,200 13,990 19,200 92.0 Br~ 78.3 72.3 100 92.3 S04= 2,575 80 10,400 3.1 TDS 29,380 23,615 47,660 80.4 pH 8.26 8.04 8.20 The results of Table 1 indicate that the mernbrane effectively excludes from the injection water product undesirable S04= ions which are precipitate precursors when contacted in situ with Ba++
resident ions. The S04= concentration in the injection water product is sufficiently low to prevent substantial pluyying in most cases when injected into a subterranean hydrocarbon-bearing forma-tion containing Ba++ resident ions. At the same time, the mem-brane allows a significant portion of the non-precursor ions to pass through the membrane into the injection water product, which can beneficially stabilize clay in situ.
'~
.` ' `
$~
-10- Docket 8600~ -A
EXAMPLE Z
Water flooding of a subterranean hydrocarbon-bearing formation~
which contains naturally occurring Ba+~ ions, with an untreated injection sea water, which has an S04= ion concentration of about 05 2800 ppm, results in BaS04 scale formation in situ. The scale plugs fluid passageways in the formation and the production tubing of associated hydrocarbon production wells. Production in one of the wells is observed to decrease from 132,000 liters of oil per hour to 33,000 liters of oil per hour due to the plugged tubing. Water pro-duced via the well contains 2000 ppm BaS04 precipitate. To prevent further plugging, the injection water is treated in a reverse osmosis unit prior to injection accordirg to the present invention.
The injection water is fed to the reverse osmosis unit at a temperature of about 25C and a pressure of abou~ 2000 kPa.
Seventy-five percent by volume of the untreated feed is recovered as treated injection wa~er product. The unit operates at a rate of 33 liters of injection water produc~ per square meter of membrane per hour. The unit is sized such that the total output of treated injection water product is 660,000 liters per hour. The S04= con-centration in the treated injectic~ water p:roduct is reduced to 6Q pEm. The entire treated injection water output of the unit is injected into the formation via injection wells in a water flooding process.
Oil and the injected water are produced from associated produc-tion wells in the formation, The produced water contains 114 ppm Z5 BaS04 precipitate, a significant reduction from the concentration of BaS04 in the produced water prior to treatment of the injection water. Furthermore, no significant decrease in oil production due to plugging is observed after treatment of the injection water.
While the foregoing embodiments of the invention have been described and shown, it is understood that all alternatives and modifications, such as those suggested and others, rnay be made thereto and follow in the scope of the invention.
.. ~
Claims (21)
1. A process for recovering hydrocarbons from a subterranean hydrocarbon-bearing formation having fluid passageways therein com-prising the steps of:
a) feeding to a reverse osmosis means an untreated injection water containing precipitate precursor ions in a concentration which would be sufficient to form insoluble salt precipitates in an amount to substantially plug fluid passageways if said untreated injection water contacted resident ions in the formation;
b) driving a portion of said untreated injection water feed across a membrane in said reverse osmosis means at a pressure above the osmotic pressure of said feed while excluding at least a portion of said precursor ions from crossing said mem-brane to produce a treated injection water product having a precursor ion concentration less than said concentration of precursor ions in said untreated injection water feed such that said precursor ion concentration in said product is insuffi-cient to form said precipitates in an amount to substantially plug the fluid passageways when said treated injection water product contacts said resident ions in the formation;
c) injecting said treated injection water product into the hydrocarbon-bearing formation via an injection well;
d) displacing the hydrocarbons with said treated injection water product toward an associated production well; and e) recovering the hydrocarbons from the formation via said production well.
a) feeding to a reverse osmosis means an untreated injection water containing precipitate precursor ions in a concentration which would be sufficient to form insoluble salt precipitates in an amount to substantially plug fluid passageways if said untreated injection water contacted resident ions in the formation;
b) driving a portion of said untreated injection water feed across a membrane in said reverse osmosis means at a pressure above the osmotic pressure of said feed while excluding at least a portion of said precursor ions from crossing said mem-brane to produce a treated injection water product having a precursor ion concentration less than said concentration of precursor ions in said untreated injection water feed such that said precursor ion concentration in said product is insuffi-cient to form said precipitates in an amount to substantially plug the fluid passageways when said treated injection water product contacts said resident ions in the formation;
c) injecting said treated injection water product into the hydrocarbon-bearing formation via an injection well;
d) displacing the hydrocarbons with said treated injection water product toward an associated production well; and e) recovering the hydrocarbons from the formation via said production well.
2. The process of Claim 1 wherein said precipitate precursor ions are anions and said resident ions are cations.
3. The process of Claim 2 wherein said anions are divalent SO4= ions.
4. The process of Claim 2 wherein said cations are selected from the group consisting of Ba++, Sr++, and mixtures thereof.
-12- Docket 860025-A
-12- Docket 860025-A
5. The process of Claim 1 wherein said concentration of pre-cursor ions in said untreated injection water feed is greater than about 500 ppm.
6. The process of Claim 1 wherein said concentration of pre-cursor ions in said treated injection water product is less than about 100 ppm.
7. The process of Claim 1 further comprising driving ions in said untreated injection water feed which remain substantially solu-ble when contacted by said resident ions in the formation across said membrane into said treated injection water product.
8. The process of Claim 7 wherein said ions which remain sub-stantially soluble in the formation stabilize clay in situ when injected with said treated injection water product into the formation.
9. The process of Claim 8 wherein said clay stabilizing ions are selected from the group consisting of K+, Na+, Cl-, Br-, OH- and mixtures thereof.
10. The process of Claim 1 wherein the fluid passageways are in a near wellbore environment of said injection well.
11. The process of Claim 1 wherein the fluid passageways are in a near wellbore environment of said production well.
12. A process for recovering hydrocarbons from a subterranean hydrocarbon-bearing formation via an associated production well having a fluid passageway therein comprising the steps of:
a) feeding to a reverse osmosis means an untreated injection water containing precipitate precursor ions in a concentration which would be sufficient to form insoluble salt precipitates in an amount to substantially plug the fluid passageways in said production well if said untreated injection water contacted resident ions in the formation;
b) driving a portion of said untreated injection water feed across a membrane in said reverse osmosis means at a pressure above the osmotic pressure of said feed while excluding at least a portion of said precursor ions from crossing said membrane to produce a treated injection -13- Docket 860025-A
water product having a precursor ion concentration less than said concentration of precursor ions in said untreated injection water feed such that said precursor ion concentration in said product is insufficient to form said precipitates in an amount to substantially plug the fluid passageways in said production well when said treated injection water product contacts said resident ions in the formation;
c) injecting said treated injection water product into the hydrocarbon-bearing formation via an injection well;
d) displacing the hydrocarbons with said treated injec-tion water product toward said associated production well;
and e) recovering the hydrocarbons from the formation via said production well.
a) feeding to a reverse osmosis means an untreated injection water containing precipitate precursor ions in a concentration which would be sufficient to form insoluble salt precipitates in an amount to substantially plug the fluid passageways in said production well if said untreated injection water contacted resident ions in the formation;
b) driving a portion of said untreated injection water feed across a membrane in said reverse osmosis means at a pressure above the osmotic pressure of said feed while excluding at least a portion of said precursor ions from crossing said membrane to produce a treated injection -13- Docket 860025-A
water product having a precursor ion concentration less than said concentration of precursor ions in said untreated injection water feed such that said precursor ion concentration in said product is insufficient to form said precipitates in an amount to substantially plug the fluid passageways in said production well when said treated injection water product contacts said resident ions in the formation;
c) injecting said treated injection water product into the hydrocarbon-bearing formation via an injection well;
d) displacing the hydrocarbons with said treated injec-tion water product toward said associated production well;
and e) recovering the hydrocarbons from the formation via said production well.
13. The process of Claim 12 wherein said precipitate precursor ions are anions and said resident ions are cations.
14. The process of Claim 13 wherein said anions are divalent SO4= ions.
15. The process of Claim 13 wherein said cations are selected from the group consisting of Ba++, Sr++, and mixtures thereof.
16. The process of Claim 12 wherein said concentration of pre-cursor ions in said untreated injection water feed is greater than about 500 ppm.
17. The process of Claim 12 wherein said concentration of pre-cursor ions in said treated injection water product is less than about 100 ppm.
18. The process of Claim 12 further comprising driving ions in said untreated injection water feed which remain substantially solu-ble when contacted by said resident ions in the formation across said membrane into said treated injection water product.
19. The process of Claim 18 wherein said ions which remain substantially soluble in the formation stabilize clay in situ when injected with said treated injection water product into the formation.
-14- Docket 860025-A
-14- Docket 860025-A
20. The process of Claim 19 wherein said clay stabilizing ions are selected from the group consisting of K+, Na+, Cl-, Br-, OH- and mixtures thereof.
21. The process of Claim 12 wherein the fluid passageway in said production well is production tubing.
Applications Claiming Priority (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US07/010,518 US4723603A (en) | 1987-02-03 | 1987-02-03 | Preventing plugging by insoluble salts in a hydrocarbon-bearing formation and associated production wells |
| US07/010,518 | 1987-02-03 |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA1282685C true CA1282685C (en) | 1991-04-09 |
Family
ID=21746122
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA000547748A Expired - Lifetime CA1282685C (en) | 1987-02-03 | 1987-09-24 | Preventing plugging by insoluble salts in a hydrocarbon-bearingformation and associated production wells |
Country Status (11)
| Country | Link |
|---|---|
| US (1) | US4723603A (en) |
| AU (1) | AU605197B2 (en) |
| BR (1) | BR8707948A (en) |
| CA (1) | CA1282685C (en) |
| EG (1) | EG18539A (en) |
| GB (1) | GB2221708B (en) |
| MX (1) | MX163086B (en) |
| NL (1) | NL190587C (en) |
| NO (1) | NO177806C (en) |
| TN (1) | TNSN88005A1 (en) |
| WO (1) | WO1988005857A1 (en) |
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-
1987
- 1987-02-03 US US07/010,518 patent/US4723603A/en not_active Expired - Lifetime
- 1987-09-22 WO PCT/US1987/002384 patent/WO1988005857A1/en active Application Filing
- 1987-09-22 AU AU81025/87A patent/AU605197B2/en not_active Expired
- 1987-09-22 GB GB8908434A patent/GB2221708B/en not_active Expired - Lifetime
- 1987-09-22 BR BR8707948A patent/BR8707948A/en not_active IP Right Cessation
- 1987-09-22 NL NL8720550A patent/NL190587C/en not_active IP Right Cessation
- 1987-09-24 CA CA000547748A patent/CA1282685C/en not_active Expired - Lifetime
- 1987-10-01 MX MX8638A patent/MX163086B/en unknown
- 1987-10-27 EG EG613/87A patent/EG18539A/en active
-
1988
- 1988-02-03 TN TNTNSN88005A patent/TNSN88005A1/en unknown
- 1988-09-29 NO NO884320A patent/NO177806C/en unknown
Also Published As
| Publication number | Publication date |
|---|---|
| US4723603A (en) | 1988-02-09 |
| NL8720550A (en) | 1989-10-02 |
| AU605197B2 (en) | 1991-01-10 |
| GB2221708B (en) | 1990-09-26 |
| GB2221708A (en) | 1990-02-14 |
| AU8102587A (en) | 1988-08-24 |
| TNSN88005A1 (en) | 1990-07-10 |
| BR8707948A (en) | 1990-02-13 |
| NO177806C (en) | 1995-11-29 |
| NL190587C (en) | 1994-05-02 |
| NO884320D0 (en) | 1988-09-29 |
| NO884320L (en) | 1988-09-29 |
| NO177806B (en) | 1995-08-14 |
| NL190587B (en) | 1993-12-01 |
| WO1988005857A1 (en) | 1988-08-11 |
| MX163086B (en) | 1991-08-19 |
| EG18539A (en) | 1993-06-30 |
| GB8908434D0 (en) | 1989-08-23 |
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